Overview of Key Water Issues Affecting the Oil

and Gas IndustryJohn Veil

Argonne National Laboratory

NPTO SeminarSeptember 11, 2002

Three Hot Issues

• Phase II Stormwater• SPCC • Section 316(b)

Stormwater Runoff - Background

• Stormwater runoff must be covered under an NPDES permit (usually general permit)– Phase I – runoff from industrial sites

and from construction sites disturbing >5 acres

– Phase II - Runoff from construction sites disturbing from 1-5 acres

• CWA exempts oil and gas exploration and production sites from stormwater permits– EPA interprets construction of lease

roads, drill pads, and other disturbed areas to be outside of the scope of the exemption

Jurisdiction• EPA delegated NPDES authority to most states

– States issue general permits• Where states do not take over program, EPA

regions issue permits• Region 6 presents particular problem for

industry– NM does not have primacy– OK and TX have primacy for all categories except

for oil and gas– Region 6 writes oil and gas stormwater NPDES

permits for these 3 heavy producing states

Region 6 Issued a Phase I Permit

in July 1998

• Permit technical requirements– must provide an ESA consultation – must provide information on whether the

activities would affect any property on the National Register of Historical Places• where effects occur, must provide written

agreement with State or Tribal Historic Preservation Officer

– must conduct inspections at least every 14 days and within 24 hours of any rainfall > 0.5“

Phase I Permit Requirements (2)

• must develop a stormwater pollution prevention plan (SWPPP)– describe BMPs (does not specify which BMPs

must be used but must use one or more as necessary)

– employ structural practices to divert flows, store flows, and/or control runoff

– provide the timing and sequence of different BMPs

– install and maintain any control measures in accordance with manufacturer's specifications

– sediment traps and ponds must be cleaned out before accumulating more than 50% of their capacity

What Is the Concern?

• EPA will issue first Phase II permit in Jan. 2003 and begin implementation in March 2003

• EPA has not discussed permit conditions, but will probably have some or all of the conditions in the Phase I permit– Suddenly, most new E&P operations will need to

get a Phase II permit before starting – The huge increase in number of permits, ESA

certifications, and historic preservation reviews is likely to cause:• delays in starting to drill (drill rig scheduling

problems)• costs for additional studies and paperwork• Some wells won’t get drilled

Next Steps

• Participate in meetings, discussions, and conference calls

• Comment on a related regulatory proposal – Effluent guidelines for construction industry

• Review and comment on draft permit, when available

• Work with EPA and OMB to make permit conditions more flexible and reasonable

SPCC – Background

• SPCC = spill prevention, control, and countermeasure

• Existing SPCC regulations have been in place since 1973– EPA has proposed a series of amendments

over the ensuing years– These were captured in final regulations

passed July 17, 2002

• New rules are more comprehensive• Many provisions that previously were

discretionary are now mandatory

                                                         

Applicability

• Expands coverage to include users of oil• Facility definition is broadened

– Can include individual pieces of equipment

• Threshold increased to 1,320 gals of oil in aboveground tanks

• Exemptions– Completely buried tanks– Containers of 55 gals or less– Tanks used for wastewater treatment (does not

include produced water treatment)

SPCC Plans

• Must be certified by Professional Engineer

• Must be reviewed following material change to facility or every 5 years

• Plan must be kept on site if facility is manned >4 hours/day

• Revision required following:– Single spill >1,000 gals– Two spills each >42 gals within 12

month period

Content of SPCC Plans

• More requirements for drawings, emergency procedures, etc.

• Option for plan to be written in non-standard format

• Periodic integrity testing of tanks and leak testing of pipes and valves

• Annual training for oil-handling employees

SPCC Plan Compliance Dates

• Any facility in operation before August 17, 2002 and having experienced a reportable release must prepare a plan in accordance with the new rule within six months and implement the plan within one year

• A facility going into operation between August 16 2002 and August 18, 2003 must implement the plan by August 18, 2003

• Existing facilities required to have a current SPCC plan and that have not experienced a reportable release must revise the current plan within six months of the new five-year expiration period of the existing plan

Requirements for All Facilities Covered by Rule

• Discharge control equipment (e.g., dikes, curbs, berms, sumps, weirs, etc.) is required for all equipment and facilities– Could include tank batteries, separators, pipes, flow

lines, etc.• Any bulk storage containers virtually any tank or

device used to store oil) must provide secondary containment– Containment must hold volume of largest container

plus stormwater– Secondary containment can only be waived if

technically impractical • High cost is not an excuse

– Any field constructed aboveground tank undergoing repair must be tested before it is placed back into service

Other Requirements for Specific Facilities• New buried piping must have protective

wrapping and coating• Drilling facilities must install blowout

prevention before drilling below casing strings or during workovers

• Additional inspections

Next Steps

• The rule was only published last month so little has been done yet

• This is a final rule so there is no opportunity to review and revisit it

• Make sure all stakeholders are aware of new requirements

316(b) - Background

• §316(b) of the CWA requires location, design, construction, and capacity of cooling water intakes to reflect best technology available to minimize adverse environmental impact

• Primarily affects power plants and manufacturing facilities that use a lot of cooling water– Also affects refineries and offshore drilling operations

• In mid-1990’s, EPA was sued by environmental groups and agreed to develop new rules

EPA’s Regulatory Schedule

Category Proposal Date Final Rule Date

Phase I - New facilities 8/10/00 - done

12/18/01- done

Phase II - Existing utility and non-utility power producers

4/9/02 - done 8/28/03

Phase III - Other existing facilities

6/15/03 12/15/04

Commonly Considered Impacts from Cooling

Water Intakes• Impingement

–Organisms are trapped on intake

• Entrainment–Organisms

pass through intake

Note: Some but not necessarily all impinged and entrained organisms are killed.

Basic Principles of Phase I Proposal• Two-track process

• Track I requires closed-cycle cooling for most facilities

• Track II allows companies to demonstrate that other measures short of closed-cycle cooling are acceptable

• EPA is currently being sued by both industry and environmental groups

Basic Principles of Phase II Proposal• Different sets of requirements for water

bodies with different presumed sensitivity• Technology based standards for

impingement mortality and/or entrainment• % reductions compared to a baseline of:

– Shoreline intake– No fish protection technology– May use mitigation methods as part of

reduction package

• Several alternative ways of complying– Cost-to-cost variance– Cost-to-benefit variance– Install closed-cycle cooling

Overview of Phase II Requirements

• All facilities must reduce impingement mortality by 80-95% and some must reduce entrainment by 60-90%

• Requirements based on water body type

Mitigation• Operator must demonstrate

that suite of mitigation measures will maintain fish and shellfish to a level comparable to that resulting from the use of CWIS technologies

• Mitigation can be part of a compliance program or the entire program

What Are the Concerns?• What will the flow threshold

be for Phase III?– 2 MGD was threshold for Phase

I

• How many offshore facilities will be included?

• What types of controls may be placed on them?

• Mobile offshore drilling facilities have different construction and design issues than fixed onshore facilities

Next Steps

• Work with EPA and industry to accurately characterize offshore drilling facilities– Cooling water intake volume– Number of facilities– Opportunities for cost-effective

retrofits

• Review EPA work regarding refineries and offer comments as necessary

Other Water Regulatory Issues

Discharge Issues– Water quality standards– Total maximum daily loads

(TMDLs)

• Wetlands

Discharge Issues• NPDES permits required

– Coal bed methane discharges

Water Quality Standards (WQS)

• EPA continues to develop new water quality criteria for toxics, nutrients, microorganisms

http://www.epa.gov/ost/standards/wqcriteria.html

• WQS used to set NPDES permit limits– Need to consider mixing zone policies– May result in very strict limits

• May serve as CERCLA or RCRA clean up standards

• If WQS are set very low, the cost of complying can be quite high

Total Maximum Daily Loads

(TMDLs)

• Maximum amount of a given pollutant that a water body can receive and still meet water quality standards– TMDLs are pollutant-specific– May need more than one TMDL for a given

water body

• Based on the capacity of the water body, not on the sources of the pollutant

Final TMDL Regulations

• Adopted in 2000• Controversial – EPA adopted this rule against

the wishes of Congress• Includes point sources and nonpoint sources

– Air deposition from utilities

• Nitrogen deposition in Chesapeake Bay watershed

• Mercury in Great Lakes• Strong potential for economic impact over 5-

20 year time frame

2000 Rule – What’s in a TMDL?

• Name of water body and pollutant• Water quality standard that must be

met• Allowable pollutant load• Load reduction needed and sources of

pollutant• Allocations for point and nonpoint

sources• Implementation plan

2000 Rule – Implementation

Plan

• List of actions needed to reduce pollutant loadings

• Time line• Reasonable assurance that implementation

will occur• Monitoring plan with milestones for

measuring progress• Plans for revising TMDL if suitable progress is

not made

Actual Example of TMDL for Mercury in the Middle and Lower Savannah

River • Acceptable instream mercury = 2.8 ppt• Using average annual flow and loading, final

TMDL is 32.8 kg/year (2/28/01)– Current loading is 58.8 kg/year– Needed reduction is 26 kg/year

• Assumes that 99% of mercury comes from atmospheric sources– Load allocation (atmospheric sources) = 0.99

(32.8) = 32.6 kg/year– Wasteload allocation (NPDES sources) = 0.01

(32.8) = 0.3 kg/year

How Will Mercury TMDL Be Achieved?

• Assumes that 44% reduction in atmospheric allocation will be met be 40%-50% reduction in mercury deposition by 2010 (CAA MACT controls)

• Assumes that NPDES permits will employ water quality based limits for mercury and some facilities will implement mercury minimization plans

Wetlands

• Many regulatory initiatives on wetlands– Nationwide permits– Mitigation banking

• Could affect ability to install, maintain, or repair pipelines or to drill wells in some areas

• There have been and continue to be precedential court decisions

• Need to follow developments to avoid costly or time-delaying rules

Conclusions

• There are lots of water issues that affect the oil and gas industry

• Some are developing and DOE can play a role in shaping their outcome

• Others are finalized and DOE can help stakeholders implement the requirements